Hydrocarbon fluids are produced by wells drilled into offshore and land-based reservoirs. The wells range in depth and length from a few hundred meters to several kilometers. Various wellbore designs (completions) are used for the different situations found in offshore and land-based hydrocarbon reservoirs. The complexity of wellbore design has increased with time, as new ways are found to produce oil and gas reservoirs more economically. Concurrently, the need for wellbore monitoring has increased, including fluid flow, wellbore condition and completion integrity.
The traditional way to measure downhole fluid flow conditions is to use a production logging tool (PLT), as presented by Hill (Hill, A. D. (1990): Production Logging—Theoretical and Interpretive Elements, Society of Petroleum Engineers, Monograph, Volume 14, 154 pp.). Such tools are primarily used to measure the downhole pressure, temperature and fluid velocity. Other properties can also be measured using PLT=s, depending on the particular wellbore condition or problem being investigated. Fluid velocity is normally measured using a spinner, as presented by Kleppan, T. and Gudmundsson, J. S. (1991): Spinner Logging of a Single Perforation, Proc., 1st Lerkendal Petroleum Engineering Workshop, Norwegian Institute of Technology, Trondheim, 69–82.
In recent years the practice of installing permanent pressure and temperature gauges has increased. Unneland and Haugland (Unneland, T. and Haugland T. (1994): Permanent Downhole Gauges Used in Reservoir Management of Complex North Sea Oil Fields, SPE Production and Facilities, August, 195–201) have estimated the pay back period for a gauge installation in a field where production is limited by well capacity. The analysis showed that running a PLT typically requires 28 hours shut-in, including shut-in of neighbouring wells for safety reasons. As individual well rates vary between 500 and 5000 Sm3/day (3000–30,000 bbl/day), this represents a significant production deferment. The cost of the deferred production depends on several parameters. A common factor to the most important parameters is that the cost is highest early in the life of the well when the information is most important.
Assuming an average oil price of 20 US$/bbl the deferred production cost for the above example, will be in the range 70,000–700,000 US$. The cost of running a PLT on an offshore platform will typically be about 100,000 US$. The cost of installing a permanent pressure gauge will be about 180,000 US$. Unneland and Haugland (1993) concluded that the average pay back period for permanent gauge installations is less than one year.
Permanent downhole gauges measure the pressure at one particular depth. They are typically installed above the perforated interval in oil and gas wells. Pressure measurements from permanently installed downhole gauges are used to monitor the pressure behavior with time in production wells; for example, for pressure transient analysis purposes. Provided fluid flow measurements are also available, the pressure measurements can be used to monitor well performance with time.
An important limitation of permanent downhole pressure gauges is that they are fixed at one location (depth). It means that permanent downhole gauges cannot be used to measure the pressure profile with depth in oil and gas wells. However, a PLT can be used to measure the pressure profile with depth, in both shut-in and flowing wells. The cost of running one PLT in typical offshore wells in the North Sea was above reported to cost 70,000–700,000 US$ in deferred production and about 100,000 US$ in direct expenses. Furthermore, when running a PLT in a flowing well, the well will normally be routed through the test separator. It means that the availability of the test separator for more routine production testing is reduced.
Multiphase metering technology for offshore and land-based oil production operations has developed rapidly in recent years and decades, as evident from the many conferences on the subject, including the North Sea Metering Conference, held alternately in Norway and Scotland. The BHR Group conference on Multiphase Production in Cannes, is another example of the importance of gas-liquid flow in hydrocarbon production and processing. Multiphase metering is also well represented at the many conferences of the Society of Petroleum Engineers. Some of the fundamentals and practical aspects of multiphase flow in petroleum production operations are presented by King (King, N. W. (1990): Multi-Phase Flow in Pipeline Systems, National Engineering Laboratory, HMSO, London.).
Multiphase metering methods, based on the propagation of pressure pulses in gas-liquid media, have been patented by Gudmundsson (Norwegian patents Nos. 174 643 and 300 437). The first of these is based on generating a pressure pulse using a gas-gun, and measuring the pressure pulse up-stream and down-stream near the gas-gun and at some distance. The second of these is based on generating a pressure pulse by closing a quick-acting valve, and measuring the pressure pule up-stream near the valve and at some distance; the pressure pulse can also be measured up-stream near the valve and down-stream near the valve and at some distance. Other pressure pulse measurement locations can also be used, depending on the metering needs and system configuration.
A production logging tool (PLT) is commonly used in flowing oil and gas wells to investigate the condition of the wellbore, in particular problems that arise with time in production wells. Such problems include tubing and/or casing failures and the deposition of solids in the wellbore. A caliper tool can be included in a PLT-string or run independently. PLTs are also used to detect which gas-lift valve is operational and whether perforations in a gravel-pack are blocked. The term pressure survey is sometimes used by operators to describe the measurement of pressure with depth in oil and gas wells.
The operators of oil and gas wells are reluctant to put tools into the wellbore, because of the risk involved. Tools sometimes become stuck in the wellbore, resulting in greater problems than what the operators wanted to investigate. Workover is a term used in the oil and gas industry when wells are being repaired. Depending on the problem that needs fixing, such operations may be preceded by running PLT=s.
The principles behind running pressure surveys in wellbores, apply also in flowlines and pipelines. Such pressure surveys/measurements can be used to detect flowline/pipeline failures and the location and magnitude of deposits such as hydrates, wax, asphaltenes and sand. The problems caused by solids deposition in hydrocarbon production and processing have been the subject of many conferences, including A Controlling Hydrates, Waxes and Asphaltenes@ in Oslo, Dec. 7–8, 1998 (IBC UK Conferences Limited). The detection of flowline/pipeline failures includes leak detection. Pressure surveys/measurements can also be used to locate and quantify the performance of flow equipment used in oil and gas production and processing.
A major problem in making pressure surveys in flowlines and pipelines carrying gas-liquid mixtures, is the great difficulty in making continuous measurements along the flow path. Instead, pipeline pressure measurements are usually made at discrete points. Due to the limited number of discrete pressure points practicable, pressure measurements in flowlines and pipelines are usually not suitable to detect and monitor deposits and leaks. Clearly, discrete measurements are more difficult in subsea pipelines than land pipelines. The only practical exception is the use of sound waves in single-phase flow pipelines to detect and locate leaks.
Objective
A main objective of the present invention is to provide a method to determine the pressure profile in wellbores, flowlines and pipelines that are flowing singlephase and multiphase fluids in the petroleum industry and related industries.
Another objective is to provide such a method which does not require expensive equipment and does not involve tools with the potential risk of getting stucked when brought into the wellbore, flowline or pipeline.
Another objective is to provide a method to determine the pressure profile with the purpose to be able to detect and locate problem areas like collapse, deposits, leakages or the like in the wellbore, flowline or pipeline.
These and other objectives are fulfilled by means of the method according to the invention.
The Invention
The invention relates to a method for determining pressure profiles in wellbores, flowlines and pipelines, said method being defined by the characterizing part of claim 1.
Preferred embodiments of the invention is defined by the dependent claims.
Furthermore, the invention relates to use of said mathod for different purposes as defined by the claims 6–12.
Mathematical Basis for the Invention
The present invention may be seen as an extension of the previous inventions of Gudmundsson (Norwegian patents Nos. 174 643 and 300 437). The previous inventions are based on the propagation of pressure waves/pulses in gas-liquid mixtures. In particular, when a quick-acting valve located near the wellhead of an offshore production well is activated, a pressure wave/pulse will be generated. The pressure pulse will propagate both up-stream and down-stream of the quick-acting valve. The magnitude of the pressure pulse will be governed by the water-hammer equation, also called the Joukowsky equation:Δp_a=ρ u a,  (1)where ρ (kg/m3) represents the fluid density, u (m/s) the fluid flowing velocity and a (m/s) the speed of sound in the fluid. The speed of sound in the fluid is equivalent to the propagation speed of the pressure pulse generated.
The magnitude of the pressure pulse generated by a quick-acting valve can be measured immediately up-stream by using a pressure transducer. In flow systems where the up-stream and down-stream pipes (wellbore, flowline, pipeline) are sufficiently long, the pressure increase immediately up-stream of the quick-acting valve, will be the same as given by the water-hammer equation.
A pressure pulse travelling into a wellbore producing an oil and gas mixture, will arrest the flow; that is, the pressure pulse will stop the flow. The pressure pulse will travel into the wellbore at the in-situ speed of sound. Therefore, the oil and gas will be brought to rest as quickly as the pressure pulse travels down into the wellbore. In principle, when the pressure pulse has reached the bottom on the well, the fluid velocity in the wellbore will be reduced to practically zero.
As the flow is brought to rest, the pressure loss due to wall friction will be made available. That is, the pressure drop due to gas-liquid mixture flow in the wellbore, will be released. This frictional pressure drop will propagate continuously to the wellhead and can be measured and is often called line-packing.
Frictional pressure drop in pipes (wellbores, flowlines, pipelines) is governed by the Darcy-Weisbach equation:Δp—f=(f/2)(ΔL/d) ρ u^2  (2)where f (dimensionless) is the friction factor, ΔL (m) pipe length, d (m) pipe diameter, ρ (kg/m3) fluid density and u (m/s) fluid velocity. The Darcy-Weisbach equation as shown here holds for single-phase laminar and turbulent flow. In principle, the equation can be extended to hold also for multiphase flow. There are many such extensions presented in various books on multiphase flow (G. Wallis, A One-Dimensional Two-Phase Flow@, McGraw-Hill, 1969, and P. B. Whalley, A Boiling, Condensation and Gas-Liquid Flow@, Oxford University Press, New York, 1987).
The Darcy-Weisbach equation can be written in terms of the pressure gradient:(Δp—f)/ΔL=(f/2)(1/d) ρ u^2  (3)
The friction factor in single-phase and multiphase flows can be obtained from semi-empirical relationships such as the Blasius-equation:f=(0.0791)/Re^0.25  (4)where Re is the Reynolds number given by:Re=(ρ u d)/μ  (5)
The Blasius-equation is used when the flow is hydrodynamically smooth. If the flow is rough, the Colebrook-White equation can be used:(1/f)^0.5=−2 log [(2.51)/(Re f^(−1))+(k—s/(3.7 d))]  (6)where k_s is the sand-grain roughness.
The density of a gas-liquid mixture is given by the relationship:ρ—M=αρ—G+(1−α)ρ—L  (7)where α (dimensionless) is the void fraction and the subscripts stand for M (mixture), G (gas) and L (liquid). In hydrocarbon production the liquid-phase will often consist of oil and water.
The speed of sound in homogenous gas-liquid mixtures a_M is given by the traditional Wood equation, here expressed as:a—M=(A B)^−1  (8)where:A=[αρ—G+(1−α)ρ—L]^0.5 and:  (9)B=[(α/(ρ—G a^2—G))+((1−α)/(ρ—L a^2—L))]^0.5  (10)Note that a_G and a_L are the speed of sound in gas and liquid, respectively. Dong and Gudmundsson (Dong, L. and Gudmundsson, J. S. (1993): Model for Sound Speed in Multiphase Mixtures, Proc. 3rd Lerkendal Petroleum Engineering Workshop, Norwegian Institute of Technology, Trondheim, 19–30.) derived a similar equation for petroleum fluids.
The above equations show that the flow in land-based and offshore wellbores, flowlines and pipelines depends on many factors. Additional factors are the pressure, volume and temperature behaviour of the fluid mixtures involved. It is convenient to illustrate the invention by assuming several of the above factors as constant. Later, in practical situations, such assumption can be relaxed and the various effects can be taken into consideration.
Assuming single-phase flow in a wellbore; assuming a constant wellbore diameter; assuming a constant friction factor; assuming a constant flowrate; assuming a constant in-situ speed of sound, and; assuming a constant fluid viscosity, the line-packing measured at the wellhead after full/complete closing of a quick-acting valve, will increase linearly with time. Furthermore, assuming that the quick-acting valve closes instantaneously, the pressure increase with time for such conditions is illustrated in FIG. 1. For any point A the pressure measured represents the wellbore line-packing the distance ΔL up-stream (into the wellbore):ΔL=0.5 a Δt  (11)where Δt (s) is the time. The factor 0.5 is applied because the pressure pulse must first travel down to point A and then back to the wellhead.
The assumption of constant wellbore diameter can be relaxed to illustrate the situation where a smaller diameter tubing is used below a certain depth; that is, an abrupt and significant step-change in diameter. The pressure increase with time for such a condition is illustrated in FIG. 2. The point B represents the distance from the wellhead to the change in tubing diameter. A part of the pressure wave/pulse is reflected from the transition and back to the wellhead, hence the step-increase in pressure, and a part of the wave/pulse is transmitted further into the wellbore. Because the tubing diameter below the depth of point B is smaller than above, the frictional pressure gradient is larger.
The assumption of a constant wellbore diameter can be relaxed to illustrate the situation where the tubing diameter has been reduced in a certain interval. The tubing diameter reduction is an abrupt and significant and exists for some distance, until the diameter expands abruptly and significantly. The pressure increase with time for such a condition is illustrated in FIG. 3. The point C represents the distance from the wellhead to the reduction in tubing diameter, and the point D represents the distance from the wellhead to the return to full tubing diameter. Such a reduction in tubing diameter may result from tubing collapse or the deposition of solids in the particular interval.
The assumption of a constant friction factor can be relaxed to illustrate the situation where the friction factor increases in a certain interval. An increase in friction factor will result in similar effects as a decrease in diameter, as evident from the Darcy-Weisbach equation. The increase in friction factor increases the frictional pressure gradient in the interval, as illustrated in FIG. 4. The point E represents the distance from the wellhead where wellbore friction increases, and the point F represents the distance from the wellhead where wellbore friction decreases. It needs to be recognised that the deposition of solids in a certain interval and resulting in reduced tubing/wellbore diameter, may be accompanied by a change in friction factor.
The assumption of constant flowrate can be relaxed to illustrate the effect of added fluid inflow at a particular wellbore depth. The pressure increase with time for such a condition is illustrated in FIG. 5. The point G represents the distance from the wellhead to the depth where the flowrate increases. The flowrate below point G is less than the flowrate above point G. Oil and gas wells are sometimes completed with more than one perforated zone, and sometimes with one or more sidetracks or multilaterals. The fluids entering a wellbore from such zones and laterals will increase the flowrate and thus affect the pressure profile.
The assumption of single-phase flow and the assumption of constant speed of sound can be relaxed together to illustrate the effect of multiphase flow in the wellbore. The viscosity will also change, but this effect will not be discussed further. The pressure increase with time for such a condition is illustrated in FIG. 6. The point H represents the distance from the wellhead to the depth where the fluid flow changes from single-phase liquid flow from below, to multiphase flow above. It is the wellbore depth where the pressure corresponds to the bubble-point pressure of the hydrocarbon fluid. Depending of the particular situation, the line-packing pressure from the wellhead to point H may or may not be linear. Non-linear effects arise because of the nature of gas-liquid mixtures and multiphase flow. In FIG. 6 the line-packing pressure below point H is shown linear, indicating single-phase flow and constant wellbore diameter.
In FIG. 5 the flowrate of liquid hydrocarbon changed at point G and in FIG. 6 the fluid flow changed from single-phase to multiphase at point H. In gas-lift wells two types of flow situations arise. First, a situation where gas enters the wellbore tubing (through a gas-lift valve) where single-phase liquid flows from below, such that gas-liquid flow continues up the tubing to the wellhead. Second, a situation where gas enters the wellbore tubing (through a gas lift valve) where multiphase gas-liquid mixture flows from below, such that a gas-rich mixture continues up the tubing to the wellhead. It should be noted that both such situations could be illustrated in figures similar to FIGS. 5 and 6. Pressure surveys in gas-lift valves can be used to locate which of several gas-lift valves is operating.
FIGS. 1–6 illustrate the increase in water-hammer pressure when a quick-acting valve is closed according to the invention, and the subsequent gradual increase in line-packing pressure with time. The figures illustrate simplified situations, and the points A–H represent for each situation a particular distance ΔL. To calculate this particular distance, fluid flow equations and fluid properties need to be known. In single-phase flow of fluids with constant pressure-volume-temperature (PVT) properties, the calculations are simple and explicit. In multiphase flow of fluids with variable PVT-properties, however, the calculations needed are more involved and implicit.
The following steps describes how the distance ΔL might be calculated for the particular situation illustrated in FIG. 6, where the point H represents the distance to the bubble-point pressure in the wellbore:                1. A pressure pulse test is made and the mass flowrate of the gas-liquid mixture flowing at the wellhead is calculated from the water-hammer equation, and the wellhead temperature is measured.        2. The pressure-volume-temperature properties of the gas-liquid mixture flowing in the wellbore are assumed known from standard oilfield practices, based on measurements and/or established correlations.        3. An established wellbore flow simulator is then used to calculate the wellbore pressure and temperature from the wellhead to downhole, including fluid densities and void fraction.        4. The speed of sound in the flowing gas-liquid mixture is then calculated piecewise from the wellhead to bottomhole, using fundamental relationships and the wellbore simulation results.        5. The time-scale in FIG. 6 is converted to distance in a piecewise manner using the relationship ΔL=0.5 a Δt.        
The above calculations can be carried out using data and models that range from simple to comprehensive. The more accurate the data and the more accurate the models, the more accurate the results. The accuracy of the calculations can also be improved by additional measurements and other information. For example, pressure measurements from a downhole gauge can be matched to the arrival of the pressure pulse. And the known locations/depths of changes in tubing diameter and other completion features, can be matched to their appearance in the line-packing signal measured at the wellhead. Similarly, downhole temperature measurements can be used to improve the accuracy of pressure profiles in wellbores; either point measurements or distributed measurements.
Distributed temperature measurements can be made using optical fibre technology. Such measurements can be made inside or outside the production tubing, and can be configured to give the temperature at fixed intervals from the wellhead to wellbottom. Distributed temperature measurements are sensitive to the start-up and shut-in of oil and gas wells. The temperature profile in a well that has produced for a relatively long time, will be more stable with time than the temperature profile in a well that has recently been started-up or shut-in (E. Ivarrud, (1995): A Temperature Calculations in Oil Wells@, Engineering Thesis, Department of Petroleum Engineering and Applied Geophysics, Norwegian Institute of Technology, Trondheim.). Distributed temperature measurements made outside the production tubing will take a longer time to respond to changes in the temperature profile inside the tubing than direct measurements (distributed temperature measurements inside the tubing).
The combination of a pressure pulse flowrate measurement, a wellbore pressure profile measurement and a distributed temperature measurement, gives similar information as obtained from running a production logging tool (PLT).